Northwest Europe, as an exploration and production province, by the late 1990s was showing signs of old age.
With the average size of remaining development prospects dwindling and operators looking to screw down costs, new technology was seen as the key to project viability.
At the Offshore Europe conference in Aberdeen during September 1999, keynote speaker Malcolm Brindred, chairman of Shell UK Ltd., prescribed technology as the key to unlocking a future for Northwest Europe`s offshore industry.
"In the North Sea," said Brindred, "we now face income per barrel down to one fifth of the early `80s in real terms, as well as new field sizes one fifth of the early `80s.
"Together, this makes a typical new project prize worth only one twenty-fifth of then. I find that a daunting prospect. We can only stay in business against this background because of the technological advances we`ve made in the last decade.
"To stay profitable in future we`ll have to find even better new technology and apply it even faster in order to explore and develop more small pockets of oil and gas at lower cost. This is not only essential to bring new fields on stream economically, but also to extend the commercial lifetime of our existing platforms."
Production levels
Yet while operators prepared to put the squeeze on this aging province, Northwest Europe`s production levels appeared vibrant.
Wood Mackenzie Consultants Ltd., Edinburgh, reported that Northwest Europe`s offshore oil and NGL production during the first half of 1999 showed an increase on the same period of a year earlier but fell short of expectations.
Combined offshore oil and NGL was said to average 6.03 million b/d in the first 6 months of the year, compared with an anticipated 6.49 million b/d. The analyst said that, despite the first half shortfall, overall production was expected to rise substantially by yearend to give a forecast average of 6.2 million b/d for the whole of 1999.
Norway`s liquids output averaged 3.06 million b/d in the first 6 months of the year, a shortfall of 173,000 b/d on Wood Mackenzie`s beginning of year forecast.
This was attributed to lower than anticipated production from a number of large mature fields, delays to the Åsgard, Oseberg Øst, and Visund developments, and teething trouble in fields which came on stream in the prior 2 years, namely Ekofisk II, Njord, Norne, and Varg.
The analyst predicted that Norway`s oil and NGL output would average 3.2 million b/d for the whole of 1999, an increase from 3.14 million b/d the previous year. "However, considerable uncertainty still remains about the performance of new and recent developments."
UK oil and NGL total output averaged 2.67 million b/d for the first 6 months of 1999, which was 272,000 b/d less than forecast. Yet production for the period was up 3% on the same 6 months of 1998, and Wood Mackenzie attributed the variation from expected performance mainly to underperformance in existing fields, with a number of floating production units suffering mechanical problems.
UK operators brought seven new fields on stream in the first half of 1999, with combined capacity to produce up to 200,000 b/d of liquids. Six further developments were expected to be completed by yearend, with a combined average output expected to be 120,000 b/d.
These new developments offshore the UK were expected to increase production significantly towards the yearend, raising average output for the year to 2.67 million b/d, a record for annual UK production and a 54,000 b/d hike on the 1998 average.
Danish oil and NGL production was said to have performed broadly as expected from January to June, averaging 273,000 b/d. Denmark`s production was expected to rise through the last 6 months of the year, boosted by completion of the South Arne development, with a new average annual production level of 304,000 b/d anticipated. This would be up 66,000 b/d from the 1998 average daily production.
Oil and NGL production offshore The Netherlands was said to show only minor variations from the forecast, with combined output averaging 25,500 b/d during the first half.
However, Dutch liquids production was expected to decline moderately during the latter half of 1999 to give an average of 25,000 b/d for the year, compared with 27,000 b/d for 1998.
Government views
Norway`s Ministry of Petroleum & Energy announced new measures to maintain activity in its offshore oil and gas industry.
The news followed the revelation that the Åsgard development by Statoil AS would exceed its budget of 28.5 billion kroner ($3.67 billion) by 17 billion kroner ($2.19 billion).
The Åsgard project overrun was one of a long list anticipated by the ministry, which discovered that Norway`s offshore operators expected to spend an extra 26 billion kroner ($3.4 billion) on 35 projects recently completed or under way.
The ministry said that there were few new development projects being brought forward by operators. "This could result in a steep fall in the activity level and employment in the sector, when the ongoing projects have been finalized."
It proposed allocating 100 million kroner ($13 million) to a program to encourage the development of project-related technology. The government expected that industry would fund the bulk of development of any technologies it financed.
"The purpose of the proposal," said the ministry, "is to secure continued profitable development of the resources on the Norwegian continental shelf and to contribute to sustained competitiveness in Norwegian industry during a period of lower activity level."
The UK Department of Trade & Industry predicted that UK liquids production would be in the range of 120-150 million tonnes/year during 1999-2001, falling to 115-145 million tonnes in 2002 and 105-135 million tonnes in 2003.
Similarly, gas output was forecast to be 90-110 billion cu m in 1999, rising to 95-115 billion cu m in 2000 and 2001 and 100-120 billion cu m in 2002 and 2003.
The DTI said 10 oil and gas field development plans were being considered, while during 1999 a further 25-30 new field and satellite development plans were expected to be submitted for approval.
The DTI said that proven remaining liquids reserves stood at 685 million tonnes at the end of 1998, down on the year from 690 million tonnes, while probable reserves fell to 575 from 700 million tonnes, and possible reserves fell to 535 from 625 million tonnes.
The DTI said that at the end of 1998 proven remaining gas reserves amounted to 755 billion cu m, down on the year from 765 billion cu m, while probable reserves fell to 585 from 620 billion cu m, and possible gas reserves dropped to 455 from 600 billion cu m.
Exploration
In 1999 came the realization that the area west of the Shetland islands, the UK`s hottest play for years, had cooled.
The last big West of Shetland discovery was the Suilven oil strike by BP Amoco PLC in March 1997, on a block near the Foinaven and Schiehallion fields which it developed subsequently.
While other operators including Texaco Ltd. and Amerada Hess Ltd. had struck oil and gas there, and while numerous others had drilled wells, BP Amoco`s finds remained the only tangible successes.
At the Offshore Europe conference R.S. Parr, D. Cowper, and B.C. Mitchener of BP Amoco`s Western Margins/Atlantic Frontiers exploration team revealed that after the initial strikes in Foinaven and Schiehallion, made in 1992 and 1993 respectively, Suilven was the most notable success.
"Several other exploration wells," said the authors, "were targeted on surrounding, more poorly defined amplitude anomalies to ascertain rapidly the potential size of the second field development.
"Often the geophysically led exploration emphasis tended to lose sight of geology, and it became apparent that seismic-driven exploration risk reduction was not a panacea and it required a significant database to discriminate hydrocarbon-related amplitudes from other facies.
"The rapid exploration pace meant there was little time to learn from previous experiences. In 1996 BP/Shell`s active exploration effort started a 4-year hiatus as a period of consolidation and understanding began."
The authors confirmed that no other operators had announced significant discoveries and that over the previous 1-2 years there had been a downturn in West of Shetland exploration because of the "generally poor success record," high costs of exploration, and low oil price.
The authors said that future exploration would be hampered by the layer of basalt which covers much of the West of Shetland area, obscuring the seismic picture of potential prospectivity below.
"In this environment," said the authors, "seismic-driven exploration is very difficult and direct hydrocarbon detection seemingly impossible.
"Considerable effort has been put into trials which would allow exploration in such environments using non-seismic methods, larger seismic sources/longer cables, and cables placed on the seabed.
"A number of wells have been targeted in these areas, but it is too early to know if the oil industry will have any significant success."
Yet there was still hope for operators, as the opening of Northwest Europe`s last true virgin play was made possible by the solution to a longstanding dispute over the maritime boundary between the UK and the Faroes Islands.
The UK Foreign Office said, "The agreement will make it possible for both parties (the Faroes are a Danish dependency) to hold petroleum licensing rounds as soon as practicable."
The DTI was keen to open up licenses along the UK offshore boundary, which runs along the northwestern extent of the West of Shetland play. The Faroese Petroleum Administration planned to offer its virgin continental shelf area to international exploration companies.
The boundary agreement was expected to be in place by the end of the 1999 summer, after which both the UK and Faroese governments would open licensing rounds "as soon as possible."
Almost immediately, Faroes Oil & Gas Co. (FK) and London-based Dana Petroleum PLC declared their intention to bid together for acreage offshore the Faroes.
Nils Sorensen, chief executive of FK, a privately owned Faroese company set up in 1997 in anticipation of licensing, said the blocks of interest were southeast of Faroese waters near the Foinaven and Schiehallion fields to the west of the UK`s Shetland Islands.
Sorensen said six or seven groups of foreign firms appeared to be interested in acquiring Faroese acreage. FK and Dana intended to strike a deal to participate in one of these groups. Faroese legislation encouraged bidders to demonstrate Faroese participation in their license bids.
Development prospects
While development activity in 1999 was comparatively low, operators brought forward a string of mainly small projects, typically involving a subsea tieback to existing infrastructure.
In March 1999 Elf Exploration UK PLC disclosed a gas/condensate discovery near its Elgin and Franklin fields, which were under development.
Joel Fort, Elf Exploration UK`s Central Graben asset manager, said the Elgin/Franklin-Shearwater area was underexplored, as was proved by the Block 29/4d find, named Glenelg.
"Early seismic did not show any prospects in this area," said Fort, "because it is very deep and the reservoirs are high pressure/high temperature structures.
"And until a few years ago we could not have developed such finds. We have had to participate in the development of HP/HT technology so we could develop Elgin and Franklin."
The discovery well flowed 23 MMcfd of gas and 2,100 b/d of "good quality" condensate from a limited section of the reservoir. Elf hoped to develop the discovery as a satellite of the Elgin field platform.
Analysts estimated Glenelg reserves at about 100 million boe. Development of Glenelg would require 15,000 psi subsea wellheads, which were not then available but were said by Elf to be under development.
In April 1999 Saga Petroleum AS, subsequently taken over by Norsk Hydro AS, submitted to Norway`s Ministry of Petroleum & Energy a plan for the development of the Borg discovery on Norwegian North Sea Block 34/7.
The find was previously known as H-Central and lay 1 km west of Saga`s Tordis field, a subsea satellite of the Gullfaks C platform. Saga planned to develop Borg initially with one subsea well tied back to the Tordis manifold. This well was tested under a 6-month production program. Saga said that Borg output was expected initially to be 15,000 b/d but that tie-in of further wells was being considered to raise production to 30,000 b/d in 2001. Borg had estimated reserves of 75 million bbl of oil. The single-well development was expected to cost 800 million kroner ($105 million).
Meanwhile, Elf Petroland BV disclosed a gas discovery on Block K5a offshore The Netherlands. Elf said the K5-11 well was drilled to a total depth of 4,140 m. It flowed 750,000 cu m/day of gas from the Rotliegendes sandstone play.
The operator said it was studying the most cost-efficient development scheme for the new discovery. This would likely involve a subsea tieback to Elf`s platforms on Blocks K4b and K5a nearby.
That same month Phillips Petroleum Co. UK Ltd. let a front-end engineering design contract to AMEC Process & Energy for development of UK North Sea Jade field.
Block 30/2c Jade was a high pressure/high temperature gas and condensate field 9 miles north of Phillips` Judy platform. Phillips chose an unmanned platform, comprising a 2,700-tonne steel jacket and 2,000-tonne topsides standing in 260 ft of water tied back to Judy platform by a 16-in. multiphase pipeline.
In May 1999 Marathon International Petroleum Ireland Ltd. let an engineering, procurement, installation and construction contract to Coflexip Stena Offshore Ltd., Aberdeen.
The contractor was to tie back the discovery well for Southwest Kinsale gas field, on Block 48/25 off Southeast Ireland, to Marathon`s Kinsale Bravo platform 7 km away.
The tie-back would be made with a 12-in. rigid flowline and umbilical, laid during the summer by the CSO Apache pipelay ship. Coflexip Stena would also modify existing installations for gas export beginning Oct. 1, 1999.
Enterprise Oil PLC received DTI approval to develop the Cook field on North Sea Block 21/20a. The field lies in 94 m of water and would be developed with two subsea wellheads tied back with an 8-in. flow line to the Anasuria production, storage, and offloading ship on Block 21/24 to the southwest, operated by Shell UK Exploration & Production.
Cook had estimated reserves of 20 million bbl of oil and 15 bcf of gas and was expected to be developed for £60 million ($100 million). Enterprise planned to bring the first well into production in July 2000 to produce up to 10,000 b/d of oil. The second well would be brought on stream in 2001 to take total production to 20,000 b/d.
In June 1999 Burlington Resources (Irish Sea) Ltd. slated development of West Millom gas field in 30 m of water on UK Irish Sea Block 113/27a with an unmanned platform.
West Millom reserves were estimated at 210 bcf of gas. Burlington planned to tie the platform back to the Morecambe North platform 9 km to the east, where Hydrocarbon Resources Ltd. was operator.
In June 1999 Texaco North Sea UK Co. let a £20 million ($32 million) contract to Coflexip Stena Offshore for pipelaying in UK North Sea Captain field. The field was being expanded, and CSO was charged with design, procurement, installation, tie-ins, and commissioning of a pipeline between the new processing platform, then under construction, and a subsea template to be installed in the east of the field. The project required laying 40 km of in-field pipelines including two 16-in. production lines, with work due for completion by July 2000.
Phillips disclosed an oil and gas discovery on Block 2/7 in the Norwegian North Sea, 7 miles west of the nearest platform in the Ekofisk complex. Phillips said the Ebba 2/7-31 well was drilled to a total depth of 16,300 ft and encountered oil and gas in the Permian Rotliegendes and Jurassic formation sandstones.
The well cut 195 ft of net pay in the Jurassic and 120 ft of net pay in the Rotliegendes. The Jurassic interval tested at a stabilized rate of 1,780 b/d of oil and 4.25 MMcfd of gas on a 16/64-in. choke at a flowing wellhead pressure of 6,570 psi. Oil was recovered by wireline sampler from the Rotliegendes, with a flow test deferred to a future well. Phillips abandoned the well and evaluated the test, core, and log data "to determine a forward appraisal program and, ultimately, the commerciality of this discovery."
At the same time Conoco (UK) Ltd. announced a gas discovery on Block 49/17 in the UK`s Southern North Sea sector. The 49/17-13 new pool wildcat was drilled with the Glomar Arctic IV jack-up rig operating in 110 ft of water.
The well was drilled to a total measured depth of 10,160 ft, cutting gas pays of 350 and 370 ft net in Rotliegendes sandstone. The well targeted a prospect known as E-Plus. Conoco planned further studies to determine the extent of the find. Options for development were said to include an unmanned minimum facilities platform tied back to Conoco`s Lincolnshire Offshore Gas Gathering System or Viking Transportation System infrastructure, both of which deliver gas to Theddlethorpe terminal.
In July 1999 BG PLC began studying development options for its Blake oil discovery in the Outer Moray Firth area of the UK North Sea, with a view to submitting a field development plan towards the end of the year. One option was a subsea development tied back to the Block 13/28a Ross field, operated by Talisman Energy (UK) Ltd.
BG said initial development plans would concentrate on the drainage of a reservoir estimated to have recoverable reserves of 50-75 million bbl of light oil. "There is also the potential to develop significant additional volumes outside the main reservoir," it said.
The 13/24b-3 discovery well, drilled in March 1997, tested a maximum 2,600 b/d of sweet 32° gravity crude oil on a 40/64-in. choke. Three appraisal wells were drilled on Block 13/24 in 1998, one of which flowed 4,000 b/d on test.
In July 1999 Norsk Hydro let a 250 million kroner ($32 million) contract to Kvaerner Oilfield Products AS, Oslo, for subsea equipment to develop Tune gas field with four subsea wells tied back via a seabed template to Oseberg field.
Tune, due on stream in 2002, has estimated reserves of 55 million bbl of condensate and 955 bcf of gas. Production peaks of 35,300 b/d of condensate and 425 MMcfd of gas were anticipated. The field lies on Norwegian North Sea Blocks 30/8 and 30/5, where water depth is about 90 m.
In August 1999 Enterprise announced test results of a second appraisal well in the Corrib gas discovery on Block 18/25 offshore western Ireland. The 18/25-1 well was drilled to 3,741 m total vertical depth into the Triassic Sherwood sandstone by the Sedco 711 semisubmersible rig.
The well flowed at up to 64 MMcfd of gas through a 1/2-in. choke at a flowing wellhead pressure of 1,653 psi. Enterprise said the flow rate was limited by the testing equipment. John McGoldrick, Enterprise`s general manager Ireland, said, "We have successfully delineated the southern end of the reservoir. The results will require further evaluation but have already demonstrated enough reserves to begin development feasibility studies."
Veba Oil & Gas Ltd. disclosed a gas discovery on Block 21/24 offshore the UK after a well was drilled under a farm-in agreement by Shell UK Exploration & Production. Shell Expro was the operator of the Guillemot West field on the same block.
Veba said the 21/24-6 new pool wildcat was drilled 8.5 km northwest of Guillemot West to a total vertical depth of 7,762 ft. The well flowed at a stabilized rate of 5,894 b/d of oil on test on a 36/64-in. choke. Interest holders for Block 21/24 outside the Guillemot license area were operator Veba 50%, Shell UK Ltd. 25%, and Esso Exploration & Production UK Ltd. 25%.
At the same time, Norsk Hydro let a 70 million kroner ($9 million) contract to Kvaerner for pre-engineering work for development of the Grane discovery offshore Norway, which had estimated reserves of 630 million bbl of oil and 360 bcf of gas.
Grane was to be developed with a fully integrated platform with a steel jacket. Pre-engineering was slated for completion by the end of July 2000 and would form the basis of a development and operation plan for submission to the Norwegian Ministry of Petroleum & Energy in late 1999.
New production
The biggest Northwest European field to be brought on stream in 1999 was Statoil`s Åsgard field in 300 m of water in the Norwegian Sea.
The continuing Åsgard project involved development of three fields with a production, storage, and offloading ship for oil, a production semisubmersible for gas, a shuttle tanker to export oil and a new trunk line to deliver gas.
Åsgard reserves were estimated at more than 2 billion bbl of oil equivalent, of which almost 60% was gas. The fields were expected to yield up to 200,000 b/d of oil, 100,000 b/d of condensate, and 1.3 bcfd of gas.
Statoil planned to increase the number of producing wells to eight and the number of gas injectors to six, which would enable an anticipated oil production of 150,000 b/d.
By the end of the 1999 weather window 13 subsea templates were to have been installed, with four more to be installed in the Midgard section of Åsgard during 2000.
With oil production being ramped up to plateau, Statoil was working to deliver first gas on Oct. 1, 2000. The production semisubmersible was due to arrive in Stavanger in September for the fitting of modules by Kvaerner at its Rosenberg yard near Stavanger. The semi was due in the field in May 2000.
Talisman reported first oil from Ross field in the UK North Sea in April. The field was developed with the Bleo Holm FPSO, owned and operated by Bluewater Marine BV, Essen, Belgium. Ross had estimated reserves of 60 million bbl of oil and 20-30 bcf of gas and was expected to produce at a peak of 40,000 b/d of oil equivalent.
In July Amerada Hess AS began oil production from South Arne field on Blocks 5604/29 and 5604/30 offshore Denmark. The first well flowed at 7,000 b/d. A total of seven wells were due to be brought on stream, of which five were predrilled. The field was developed with a production platform with capacity to process 50,000 b/d of oil and 70 MMcfd of gas. The field has estimated reserves of 60 million bbl of oil and 80 bcf of gas.
In August 1999 Mobil North Sea Ltd. produced first oil in Buckland field on UK Block 9/18. Initial production was 16,000 b/d, but this was expected to increase to 30,000 b/d. The field was developed as a subsea satellite of Mobil`s Beryl Alpha production platform 10.5 km away on Block 9/13.
In September 1999 Talisman produced first oil from Orion oil field offshore the UK. Orion was developed as a single well subsea satellite of Talisman`s Clyde platform, to which it was tied back with a 16 km, 10-in. pipeline. The operator said production would be built up to 7,000 b/d of oil and 16 MMcfd of gas.
Earlier, Shell Expro started oil production from an additional subsea satellite of UK North Sea Gannet field, called Gannet G. Production was started through a single wellhead connected by a 5 km pipeline to the Gannet platform. A second producer was expected to be drilled. The development was budgeted at £40 million ($64 million).
Gannet G had estimated reserves of 13 million bbl of oil equivalent. Initial oil output was 7,500 b/d. While small, Gannet G was thought typical of developments to come.
Chris Finlayson, Shell Expro`s oil director, said, "Gannet G is an example of a relatively small project which has been pursued despite the recent low oil price because the development is close to, and will utilize, our existing infrastructure.
"Gannet G highlights the fact that the continued drive to cut costs of new projects by applying new technology, standardization, and good supply-chain management is bearing fruit and unlocking some small marginal developments."
 |
The Elgin/Franklin production-utilities-quarters platform takes shape at Barmac`s Nigg yard, Ross-shire. Photo courtesy of Elf Exploration UK PLC.
 |
A towhead enters water during launching of the Elgin/Franklin flowline bundle. Photo courtesy of Elf Exploration.
 |
Subsea pipeline connection unit being loaded out ready for installation on the link between Elf`s Elgin and Franklin fields. Photo courtesy of Elf Exploration
 |
The Bleo Holm moves under tow in the Firth of Clyde en route to Ross/Parry field off the UK.
 |
Shell U.K. Exploration & Production finally disposed of the derelict Brent Sea loading buoy in 1999. Here a slice of the concrete hull is being laid in place as part of a new quay in a harbor near Stavanger. Photo courtesy of Shell.
 |
The CSO Apache pipelay ship in the summer of 1999 was to lay a 12-in. rigid flowline and umbilical to tie Marathon International Petroleum Ireland Ltd.`s discovery well for Southwest Kinsale natural gas field off Southeast Ireland to the Kinsale Bravo platform 7 km away.
